Gas turbine combined cycle system

ABSTRACT

In a combined cycle gas turbine configuration having at least two power blocks, stack emissions (particularly nitrous oxides or NOx but also carbon monoxide CO and unburned hydrocarbons, UHC) are controlled concurrently with part load power output. In one power block a combined cycle power plant has a relatively large heavy-duty industrial gas turbine fired to about 1,700° C. at the turbine inlet leading to a first heat recovery system. A second power block with a smaller gas turbine has a second heat recovery system. A controller adjusts coupling of flue gas and steam paths from the second power block to the first power block to meet load demand in compliance with applicable emissions regulations.

CROSS-REFERENCE TO RELATED APPLICATION

This application claims the benefit of U.S. Provisional Application No. 61/820,901, filed May 8, 2013.

FIELD

This disclosure concerns the field of gas turbines and in particular provides methods and apparatus for managing stack emissions (e.g., nitrous oxides (NOx), carbon monoxide (CO), unburned hydrocarbons (UHC) and the like), while concurrently controlling load power output. The invention is particularly applicable to combined cycle power plants with heavy-duty industrial gas turbines, fired, for example, to 1,700° C. (3,092° F.) at the turbine inlet.

BACKGROUND

The term “combined cycle” generally refers to an assembly of two or more engines driven from the same source of heat, converting heat energy into mechanical energy, usually to drive one or more electrical generators. In gas turbine (GT) combined cycle plants, expansion of product gas resulting from combustion of fuel turns a gas turbine. Hot exhaust gases from the gas turbine are the heat source for generating steam in a heat recovery steam generator (HRSG).

Combining two or more thermodynamic cycles reduces the energy released as wasted exhaust heat. One combination comprises a gas turbine (operating by the Brayton cycle) fueled by natural gas or synthesis gas from coal. The hot exhaust from the gas turbine powers a steam power plant (operating by the Rankine cycle).

Advantageously, the combined cycle plant is operated cleanly and efficiently. An important parameter controlling the efficiency of a gas turbine combined cycle power plant is the maximum temperature of the gas turbine Brayton cycle. Strictly speaking, the highest temperature found in the gas turbine cycle is the flame temperature in the combustor, which is well above 3,000° F. But in practical terms, a logical choice for a control parameter is the combustor exit temperature, after dilution with combustor liner cooling flow and before the inlet to the turbine section. This temperature is commonly referred to as Turbine Inlet Temperature (TIT). Another commonly used engineering proxy for cycle maximum temperature is the temperature of hot combustion gas at the inlet of the stage 1 rotor or bucket (“S1B”) before the gases start to produce useful turbine work. This temperature is commonly known as the “Firing Temperature” and in F class gas turbines it is about 200° F. or more lower than the hot gas temperature at the combustor exit (at the inlet of stage 1 vane or nozzle, S1N, i.e., the “true” TIT). Thus, another term for Firing Temperature is Rotor Inlet Temperature (RIT), where the referenced rotor is the stage 1 rotor. That temperature is about 100° C. higher than the fictitious temperature defined in the ISO-2314 gas turbine acceptance standards adopted by European OEMs.

Modern gas turbine combined cycle apparatus are exemplified by advanced F, G, and H class units with TITs greater than 1,500° C. About 60% gas turbine combined cycle (GTCC) net efficiency has been achieved with these advanced units.

The design of high efficiency, high temperature gas turbines presents challenges including (1) cooling of the turbine hot gas path (HGP) components operating at such high temperatures; and (2) control of NOx and CO emissions. Cooling is advantageous to achieve acceptable parts life. Increasingly stringent emission limits are being imposed by regulatory agencies.

Techniques for accommodating high temperatures include using advanced nickel-based superalloys and casting techniques (e.g., single crystal) for turbine elements, accompanied by ceramic-based thermal barrier coatings (TBC), stationary and rotating airfoils of the first turbine stage (commonly known as nozzles/vanes and buckets/blades, respectively). Even when using the most advanced materials and coatings, cooling of HGP components by air extracted from the compressor discharge is necessary to ensure feasible parts life. Turbine HGP cooling by compressor extraction air is detrimental to gas turbine performance in at least two aspects. One aspect of introducing “cold” air into the hot combustion gas stream is to reduce the gas temperature between the turbine inlet and the stage 1 rotor inlet (where the gas starts generating useful shaft work). Thus, in order to achieve a desired firing temperature, the gas turbine combustor needs to be fired that much harder, with direct impact on NOx emissions. Another aspect of air cooling is that the air used to cool the stage 1 rotor does not produce useful shaft work. The cooling air limits the desired impact of higher firing temperatures.

One possible solution to this two-pronged problem would be to develop materials that require little or no cooling. It may be possible at some point to extend ceramics used in TBC to monolithic ceramic materials useful in stationary and rotating components. Such developments remain a major challenge. Combining the heat resistance of ceramics with the strength of metal (ceramic by itself is brittle), a ceramic matrix composite (CMC) may be a candidate to solve the cooling problem of turbine HGP components at very high temperatures. But commercialization seems to be decades off.

One existing technology in this regard is closed-loop steam cooling of turbine HGP components. In particular, General Electric's H-System™ with two stages (stages 1 and 2) fully steam cooled (i.e., both stationary and rotating components); and Mitsubishi Heavy Industries' (MHI) G and J class machines with steam cooling of combustor transition piece (the duct between the combustor exit and turbine inlet) and turbine blade rings (shrouds).

Steam cooling in a closed loop (i) reduces the temperature dilution between combustor exit (i.e., turbine inlet) and stage 1 rotor inlet and (ii) releases cooling air for work production in the turbine (in H-System™). Thus, for example, by cooling stage 1 vanes with steam imported from the bottoming cycle, the difference between TIT and firing temperature can be reduced from greater than 200° F. to about 60-80° F. This results in an increase of firing temperature at the same TIT (that is, at the same level of NOx emissions). Alternatively, it allows the deployment of parts with current materials and coating technologies, at higher TIT.

One drawback of steam cooling technology is a lack of “flexibility”. Specifically, the availability of steam (or the lack of it) during the early phase of combined cycle startup slows down the process until enough steam is generated in the HRSG to supply the gas turbine. An auxiliary boiler might be utilized instead to provide cooling steam during startup, but at the expense of additional startup fuel consumption and emissions, and at additional capital cost.

Apart from cooling problems, NOx emissions remain an obstacle in the path of ever-rising TITs. NOx is a generic term for nitrous oxides NO and NO₂ (nitric oxide and nitrogen dioxide). They are produced from the reaction of nitrogen and oxygen gases in the air during combustion, especially at high temperatures. NOx gases react to form smog and acid rain as well as being central to the formation of tropospheric ozone. Levels of NOx emission are strongly related to the flame temperature in the combustor's primary zone.

Since the flame temperature is directly related to TIT, a change in TIT from 1,600° C. to 1,700° C., for example, may increase NOx emissions in Dry Low NOx (DLN) combustors by 150% to 250%.

One possible method to control the NOx emissions is to reduce the flame temperature in the primary flame zone of the DLN combustor by introducing a diluent into the fuel-air mixture. The diluent may act as a heat sink. In earlier generations of industrial GTs with diffusion combustors, this was done by injecting water or steam into the combustor. In DLN combustors, diluent water injection is only used when burning liquid fuel (e.g., #2 fuel oil). Another possible method of introducing H₂O as a diluent into the combustor is via fuel gas moisturization (employed by General Electric's H-System™). A method used in internal combustion is to recirculate the exhaust gas and dilute the combustion motive air while increasing its CO₂ content. This is known as Exhaust Gas Recirculation (EGR). EGR can be accomplished in two ways:

-   -   Introducing the HRSG stack gas into the inlet of the compressor;         or     -   Compressing the HRSG stack gas up to the GT casing pressure         using a separate compressor and mixing it with fuel gas prior to         introducing it into the combustor to be burned.

The EGR method can be used with DLN as well as diffusion combustors. Studies show that at a temperature of 1,700° C., the lowest level of NOx concentration is obtained in the diffusion type combustor when the recirculation ratio is increased to about 35%.

Another item of interest in terms of flexibility of large gas turbines is the ability to run at a part load with maximum possible efficiency and full emissions compliance. A gas turbine is said to run at full load at given site ambient conditions when two conditions are satisfied: the gas turbine inlet guide vanes are at their normal fully open position; and the gas turbine is fired to its rated firing temperature based on its normal full load control curve.

The term “base load” typically applies to gas turbine full load at a specific site ambient condition, e.g., ISO conditions of 59° F. (15° C.), 60% relative humidity and 14.696 psia (1 atmosphere). A gas turbine is said to run at “part load” when its power output is less than it would be if it were running at full load at a given site ambient conditions.

For maximum combined cycle efficiency, gas turbine part load is controlled first by closing the inlet guide vanes (IGVs) and reducing the airflow at the same firing temperature. This reduces cycle pressure ratio and increases the exhaust temperature for maximum contribution from the bottoming cycle (i.e., the steam turbine). When the exhaust temperature reaches a certain limit (commonly known as the exhaust isotherm, typically around 1,200° F.), the gas turbine controller starts reducing the fuel flow, and consequently the firing temperature, while keeping the exhaust temperature at its maximum value. Once the IGVs reach their fully closed position (i.e., minimum airflow), further reduction in output is achieved by reducing the fuel flow, and exhaust temperature starts going down, with further detrimental impact on the contribution of the bottoming cycle.

With multiple gas turbine plants such as 2×1 (two GTs with two HRSGs and one steam turbine, ST) one can turn one GT off to achieve 50% or lower plant load with improved heat rate (compared to 1×1 plants). In general, GTCC plants with advanced gas turbines utilizing DLN combustors cannot be turned down below 30-40% load and still be emissions compliant. One exception is the sequential combustion gas turbines (also known as reheat gas turbines) with two combustors, which can turn down the second (downstream) combustor at low loads with better efficiency while maintaining emissions at allowable limits.

One possible method to reduce the GT output while maintaining the IGVs at their fully open position is to increase the temperature of the compressor airflow. This leads to reduced density and mass flow rate and has a similar effect on the GT as if it were operating on a hot day. It can be shown that at the same level of part load (i.e., same megawatt output), this method results in a better CC heat rate while also helping to reduce the emissions. There are several ways to accomplish this effect, as described in e.g., U.S. Pat. No. 7,305,831, which is hereby incorporated by reference in this disclosure.

SUMMARY OF THE INVENTION

An object of the present disclosure is to optimally limit NOx emissions over a range of plant loading conditions. Two different classes of gas turbines are operated in a combined cycle configuration for concurrent optimized control of NOx emissions and plant load. One gas turbine advantageously is an F, G, H or J class heavy-duty industrial machine with very high TIT (up to 1,700° C.) and commensurate airflow to achieve 300 MW or higher power output (henceforth, HDGT for Heavy Duty Gas Turbine). The other gas turbine advantageously is a smaller gas turbine. Ideally, the smaller gas turbine is an aero-derivative GT such as General Electric's LMS100™. The invention also can be applied to other gas turbines, preferably wherein a smaller GT has a power output and airflow about one third of that of the larger HDGT.

Thus, according to one aspect, the exhaust gas of a smaller GT generates steam in a small HRSG, and that steam is used in cooling the hot gas path (HGP) components of the larger GT.

In one embodiment, part or all of the HRSG stack gas is divided into two streams. One stream is coupled into the compressor inlet of the larger GT for load control. Another stream is coupled into a gas compressor on the same shaft as the smaller GT to be compressed and fed into the combustor of the larger GT for NOx control. As used in this disclosure, terms such as “coupled” and “connected” are intended to denote operational relationships, and although direct connections are possible, the terms do not exclude indirect operational connections such as couplings through intervening elements.

Hot water generated in the economizer of the small HRSG is injected into the hot flue gas downstream of the first gas compressor for intercooling. Steam generated in the small HRSG is heated to a prescribed temperature in an aftercooler (AC) downstream of the second gas compressor (e.g., 650° F. or ˜350° C.). Following the AC, compressed hot flue gas is cooled in a trim cooler (as needed) and mixed with fuel gas prior to entry into the fuel skid of the larger GT.

The term “exhaust gas” is used henceforth in this disclosure for the exhaust gas of the gas turbine between the exit of the gas turbine and the exit of the last HRSG heat exchanger section (e.g., a low pressure economizer) before the stack (flue). Once beyond the HRSG, the exiting gas is referred to as flue gas.

The foregoing and other objects and advantages are provided in a gas turbine combined cycle system with a first combined cycle power block with a heavy duty gas turbine operated at high turbine inlet temperature, up to 1,700° C., together with a smaller gas turbine combined cycle power block, wherein at least one of the two material streams, flue gas and steam, from the smaller power block is introduced into the heavy duty gas turbine of the first power block to control the gas turbine NOx emissions and power output (load). Requisite controls are implemented to optimize operating parameters while meeting emissions-compliant load requirements.

The first power block has a first gas turbine configured as a prime mover, a first heat recovery steam generator coupled to an exhaust path of the first gas turbine, and a steam turbine coupled to a steam outlet of the steam generator. The steam turbine also is configured as a prime mover, and at least these two prime movers drive an electric generator. The smaller at least one additional power block has a gas turbine configured as a prime mover thermally coupled to a second heat recovery steam generator. A controller is coupled to provide and/or to adjust a flow of at least one of flue gas and steam from the additional power block to the first power block. This flow concurrently adjusts a power output level of the first power block and a level of potentially harmful emissions from the first gas turbine at specified turbine inlet temperature, which can be as high as 1,700° C.

In one embodiment, a flue gas compressor, mechanically driven from one of an electric motor or a shaft of the gas turbine of the additional power block, injects part of the flue gas from the additional power block into the combustor of the gas turbine of the first power block for reducing the NOx emissions.

The various prime movers can be coupled to apply torque to separate electric generators or can be mechanically coupled by gears and clutches to drive a single shaft coupled to an electric generator.

Advantageously, the gas turbine prime mover of the first power block can include a frame machine of one of an F, G, H or J class, with a firing temperature up to 1,700° C. By controlling the combustion oxygen content via exhaust gas recirculation, the level of emissions is controlled, especially that of NOx.

The gas turbine prime mover of the at least one additional power block can include an aero-derivative unit having a high cycle pressure ratio and high cycle efficiency. The power output and airflow of the additional power block are a fraction of that of the gas turbine prime mover of the first power block. The flue gas compressor driven from the additional power block can be a multi-casing unit with at least two casings (sections). Intercooling can be provided between sections of the flue gas compressor.

Flue gas from the heat recovery steam generator of the at least one additional power block is coupled to the first gas turbine (i.e., the large heavy duty gas turbine with very high TIT in the first power block). This coupling can be made at one of a gas turbine compressor inlet and a gas turbine combustor fuel inlet. The second heat recovery steam generator is coupled to the first gas turbine at one or more entry locations on the turbine casing, so as to contribute steam for cooling of components subjected to hot combustion gases.

In one embodiment, an aftercooler heat exchanger is placed downstream of the flue gas compressor. Steam is heated in the aftercooler heat exchanger before entry into a second gas turbine prime mover.

Feed water from the second heat recovery steam generator can be coupled to a flue gas compressor intercooler for direct contact heat exchange between hot compressed flue gas from an upstream compressor section and the feed water. Precooler and trim cooler water-to-flue-gas heat exchangers can be provided upstream and downstream of the flue gas compressor aftercooler. Such heat exchangers are configured to adjust flue gas compressor suction and discharge gas temperatures. The adjustments are made by a programmed controller based on sensed inputs including load demands, temperatures, pressures, flow rates, ambient conditions and the like.

In addition to a system, the invention encompasses a method for adjusting the load of a first gas turbine, and related exhaust emissions levels thereof. This method involves apportioning flue gas from a second heat recovery steam generator between a compressor and combustor fuel inlet of the first gas turbine, steam flow to the first gas turbine for hot gas path component cooling and feed water flow to an intercooler of a flue gas compressor. The flows that are advantageously controlled and adjusted include the flue gas flow from the second heat recovery steam generator to the first gas turbine compressor inlet; the flue gas flow from the second heat recovery steam generator to the fuel gas compressor and, subsequently, to the first gas turbine combustor fuel inlet; the steam flow to the first gas turbine and its temperature, controlled via an aftercooler; a feed water flow from the second heat recovery steam generator to a fuel gas compressor intercooler; cooling water flow to a flue gas compressor precooler; and cooling water flow to a flue gas compressor trim cooler. These adjustments can be sequential, concurrent or grouped for establishing and maintaining predetermined conditions.

At least the foregoing flows and potentially additional operational parameters are monitored and controlled by coupling a controller to at least the first gas turbine and associated flow paths. The controller is responsive to temperature, pressure, flow and load sensors, and apportions flows by generating control outputs to associated valves and switches.

Among other control objects, the controller is arranged to provide a high turbine inlet temperature at the first power block, for power generation efficiency as a function of fuel burned, but without producing undue levels of undesirable exhaust emissions such as NOx, CO and UHC.

BRIEF DESCRIPTION OF THE DRAWINGS

Embodiments of the invention will now be described with reference to the accompanying drawing.

FIG. 1 is a schematic view of an embodiment of the present invention.

DETAILED DESCRIPTION OF EXEMPLARY EMBODIMENTS

An exemplary embodiment as shown in FIG. 1 has two power blocks. Power Block 1 comprises a first gas turbine (GT #1) and a steam turbine (ST), labeled but not shown as a separate block, on a single shaft driving a single generator or each driving its own generator in a multi-shaft configuration. Power Block 2 comprises a second gas turbine (GT #2) and an intercooled, two-stage flue gas compressor (FGC) on a single shaft with a single electric generator.

The gas turbine prime mover of each power block burns fuel and is thermally coupled to a heat recovery steam generator HRSG via the exhaust of the respective prime mover, i.e., GT #1 supplies hot exhaust gas to HRSG #1 (labeled but not shown as a separate block) and GT #2 supplies hot exhaust gas to HRSG #2.

The shaft configuration of Power Block 2 is not critical to the invention. That is, Power Block 2 can be a single-shaft or multi-shaft configuration. In a multi-shaft configuration, the FGC can be driven by an electric motor. Depending on the size of the system in question, this motor can be as large as 50 MW or even greater. As such, it is an expensive component of a size beyond the capability of most manufacturers. In a single shaft configuration as shown in FIG. 1, the FGC is connected to the GT #2 generator via a clutch and gear box (if necessary). Thus, Power Block 2 can operate when Power Block 1 is shut down and the FGC is disengaged. Power Block 2 is of a smaller load rating the Power Block 1, and independent operation of Power Block 2 is advantageous, for example to handle overnight low load operation and similar situations.

Referring to FIG. 1, Power Block 2 (at the top section of the FIGURE) has three products:

-   -   HRSG stack gas (also known as flue gas) for part load (megawatt         output) and combustor NOx emissions control of the GT #1         (labeled 1 and 2).     -   Medium pressure steam (labeled 3) for cooling of HGP components         of the GT #1.     -   Low pressure feed water for intercooling of compressed flue gas         (labeled 4).

A controller preferably receives as inputs data or signal levels at least representing: Site ambient conditions (temperature and humidity in particular); operator's load demand (a megawatt power output target); and for GT #1, pressure ratio (or compressor discharge pressure), compressor discharge temperature and exhaust temperature.

The controller preferably applies a programmed control algorithm, which can be based on a full thermal model of GT #1 (commonly known as a Model Based Control or MBC as known in the art) or on pre-calculated curves or on other similar methods, the controller generates the following outputs:

(1) Apportioning of the cooled GT #2 exhaust gas flow at the exit of HRSG #2 between: (a) GT #1 compressor inlet for GT #1 megawatt output control (at part load) via increased inlet temperature and reduced airflow; (b) GT #1 combustor inlet via mixing with fuel gas (following compression in the FGC); and (c) HRSG #1 stack (of the remainder, if any).

(2) Steam flow and temperature to GT #1 for HGP component cooling (typically, 650 psia and 650° F., to be determined by the GT OEM). As shown in FIG. 1, HRSG #2 utilizing the exhaust of GT #2 can generate about 50 pps (180,000 pph) saturated steam at 675 psia. Ultimately, the cooling steam requirement is determined by the cooling duty, which is a direct function of the HGP parts to be cooled (e.g., combustor liner and the transition piece in G and J class machines, stage 1 nozzles, etc.). It is highly likely that all available steam will be used on occasion, and advantageously can be supplemented by additional steam from HRSG #1.

(3) Feed water flow to the intercooler (a direct contact heat exchanger similar in principle to the GT inlet evaporative coolers) of the FGC to maintain a nearly saturated and cooled exit gas stream (e.g., 95+% relative humidity at around 230° F.). For a system shown in FIG. 1, this flow can be as high as 15-16 pps (about 40-50% of GT #1 fuel gas flow).

(4) Precooler cooling water flow to maintain FGC inlet temperature at a set value (e.g., 125° F.).

(5) Trim cooler cooling water flow to maintain mixed fuel-flue gas temperature at a set value (e.g., 450-500° F.).

Note that EGR and steam cooling can be accomplished in a single 1×1 GTCC configuration with an advanced HDGT such as Mitsubishi Heavy Industries or MHI's J class GT. Steam cooled GTs such as General Electric's H-System™ and MHI's G class units have been operating in the field for more than a decade.

Among other advantages, the present invention can afford some or all of: (1) precise, simultaneous control of NOx emissions and part load at any given site ambient condition with better GTCC plant heat rate; (2) a lower GTCC MECL (Minimum Emissions Compliant Load), especially with diffusion combustors; (3) by supplementing flue gas from HRSG #2 with water injection (for intercooling), improvement in NOx control capabilities using the moist gas stream (about 19% H₂O by volume). For a given NOx target, this reduces the amount of gas to be compressed and reduces parasitic power consumption; (4) performance fuel gas heating to 450-500° F. via direct contact heat exchange; (5) overnight parking of the plant at low load by shutting down GT #1. GT #2 can run at a relatively high simple cycle efficiency and HRSG #2 provides steam for maintaining the ST seals and condenser vacuum as well as for HRSG #1 sparging to keep the unit warm for the next startup; and (6) following an overnight or weekend shutdown, GT #1 can start up in a fast start mode by utilizing steam available from HRSG #2 for HGP component cooling. Without the aforementioned features enabled by the present invention, this might only have been possible by an auxiliary (fired) boiler to generate seal and sparging steam overnight (or over a period of days) and GT cooling steam during startup. In addition to extra capital cost, this entails extra fuel consumption and emissions with no megawatt generation.

All patent and other documents cited herein are hereby incorporated by reference in their entireties. Although the invention has been described in terms of exemplary embodiments, it is not limited thereto. Rather, the appended claims should be construed broadly, to include other variants and embodiments of the invention, which may be made by those skilled in the art without departing from the scope and range of equivalents of the invention. 

What is claimed is:
 1. A gas turbine combined cycle system comprising: (a) a first power block with a first gas turbine configured as a prime mover, a first heat recovery steam generator coupled to an exhaust path of the first gas turbine, and a steam turbine coupled to a steam outlet of the steam generator, the steam turbine being configured as a prime mover, wherein the first power block drives an electric generator; (b) at least one additional power block with a gas turbine configured as a prime mover thermally coupled to a second heat recovery steam generator; (c) wherein a controller is coupled to provide a flow of at least one of flue gas and steam from the additional power block to the first power block, said flow concurrently adjusting a power output of the first power block and a harmful emission level of the first gas turbine.
 2. The system of claim 1, further comprising a flue gas compressor, mechanically driven from one of an electric motor and a shaft of the gas turbine of the additional power block.
 3. The system of claim 1, wherein at least two of the prime movers are mechanically coupled to drive a single shaft coupled to the electric generator.
 4. The system of claim 1, comprising a multi-shaft configuration wherein each of the prime movers is coupled to a respective electric generator on a shaft.
 5. The system of claim 1, wherein the gas turbine prime mover of the first power block comprises a frame machine of one of an F, G, H or J class, with a firing temperature as high as 1,700° C.
 6. The system of claim 1, wherein the gas turbine prime mover of the at least one additional power block comprises an aero-derivative unit having a high cycle pressure ratio and high cycle efficiency, and a power output and airflow that is a fraction of that of the gas turbine prime mover of the first power block.
 7. The system of claim 1, wherein the flue gas compressor comprises a multi-casing unit with at least two casings, and further comprising intercooling between sections of the flue gas compressor.
 8. The system of claim 1, wherein flue gas from the heat recovery steam generator of the at least one additional power block is coupled to the first gas turbine at one of a gas turbine compressor inlet and a gas turbine combustor fuel inlet.
 9. The system of claim 1, wherein the second heat recovery steam generator is coupled to the first gas turbine at one or more entry locations on the turbine casing, so as to contribute cooling of components subjected to hot combustion gases.
 10. The system of claim 1, further comprising an aftercooler heat exchanger downstream of the flue gas compressor, wherein steam is heated before entry into a second gas turbine prime mover.
 11. The system of claim 1, wherein feed water from the second heat recovery steam generator is connected to a flue gas compressor intercooler for direct contact heat exchange between hot compressed flue gas from an upstream compressor section and said feed water.
 12. The system of claim 10, further comprising precooler and trim cooler water-to-flue-gas heat exchangers upstream and downstream of the flue gas compressor aftercooler, wherein said heat exchangers are configured to adjust flue gas compressor suction and discharge gas temperatures.
 13. A method for adjusting a load of a first gas turbine and related exhaust emissions thereof, comprising: apportioning flue gas from a second heat recovery steam generator between a compressor and combustor fuel inlet of the first gas turbine, steam flow to the first gas turbine for hot gas path component cooling and feed water flow to an intercooler of a flue gas compressor, including adjusting: (a) flue gas flow from the second heat recovery steam generator to the first gas turbine compressor inlet; (b) flue gas flow from the second heat recovery steam generator to the fuel gas compressor and, subsequently, to the first gas turbine combustor fuel inlet; (c) steam flow and temperature to the first gas turbine, via an aftercooler; (d) feed water flow from the second heat recovery steam generator to a fuel gas compressor intercooler; (e) cooling water flow to a flue gas compressor precooler; and (f) cooling water flow to a flue gas compressor trim cooler.
 14. The method of claim 13, further comprising coupling a controller to least the first gas turbine and associated flow paths for sensing operational parameters and wherein the apportioning comprises generating control outputs to associated valves.
 15. The method of claim 13, wherein said exhaust emissions comprise NOx, CO and UHC.
 16. The method of claim 13, wherein said adjusting is sequential along steps (a) through (f). 